Archie's assumption of saturation exponent equal 2 is valid only when the reservoir and the core are strongly water wet, the saturation exponent has been proven by many researchers, its strongly related to the reservoir wettability, pore-size distribution and displacement history and it can vary between 2 to 10 in value. Determination of fluid saturations from electric well logs adopts a calculation procedure, which is highly sensitive to several parameters one in a particular saturation exponent (n). An accurate determination of initial oil in place in the early life of reservoirs or an evaluation of a developed reservoir is requires high accuracy water saturations (Sw) values. This paper presents innovative petrophysical workflow using water saturation, true resistivity and reservoir total porosity values as inputs data; the geological zonation is critical; each selected zone will be cross-plotted to evaluate cementation exponent through Pickett plot and the irreducible water saturation factors using Sw-Phi crossplot. The mathematical derivation was done to develop a relation between the true formation resistivity (Rt) and the reservoir porosity in the irreducible water saturation intervals to predict saturation exponent utilizing the crossplot. Case studies from three different giant oil fields located in the south of IRAQ have been selected to represent various applications scenarios of carbonate and shaly-sand oil-bearing formations to test the applicability of the proposed model. Each field has a different set of data and requires a special treatment, varied from special and convectional core analysis, pressure test and NMR to only fullset of wireline data. A quality verification for Archie saturation exponent "n" values has been done quantitatively with core analysis and qualitatively with in-situ and/or core wettability. The proposed model success to evaluate saturation exponent for the studied reservoirs and show convergence with the verification methods. It is concluded that the developed petrophysical workflow of this study provides a significant contribution to the determination of water saturation exponent (n) in simplified-robust way and consequently leads to better water saturation (Sw) estimation values, and it can be applied in any carbonate or shaly-sand reservoirs worldwide.

In this study, an integrated approach of advanced spectral noise and high-precision temperature logging with production logging tool was used for the understanding of leak detection, fluid cross-flow, flow below spinner threshold, packer failure, fluid channeling in patchy and bad cement bond behind the casing, flow quantification in complex SSD completion, production detection and quantification in recirculation intervals in deviated wells. Various case studies from Southern and Northern Iraqi oil fields have been presented in this paper.

Optimizing Oil Recovery requires understanding of formation wettability; numerous characteristics of reservoir performance influenced by the oil versus water wetting preferences mainly in Enhanced Oil Recovery (EOR) practices and water flooding assuming a water-wet reservoir, if it is not, a permanent reservoir damage is expected. Oil Companies depend on the Core-Measured-wettability. The practice of transferring the samples from the formation to the lab may lead to wettability alteration during core cutting operations and sample preparation; additional laboratory issues include surface adsorption equilibrium and optimal interface-ageing time, if a smooth surface is used it will not account for the rock surface roughness. The biggest disadvantage of the laboratory methods is that of scaling to entire reservoir extent downhole condition. Adding up, all of these processes are time-consuming, consequently a technique to evaluate in-situ wettability is desired. The in-situ wettability of rocks from Nuclear Magnetic Resonance (NMR) log is a representative of the entire interval at the reservoir condition. A derived spin-lattice function from the fundamental NMR relaxation time T2 is directly related to the interfacial tension and the surface wetting fluid properties, as a result, an in-situ wettability index could be computed from the function. Rock wettability may explain some apparent discrepancies that occur in defining water-oil contacts by Reservoir Characterization Instrument (RCI) and logging measurements. Analyzing these discrepancies using the RCI Pressure Data makes it possible to estimate the In-Situ Wettability state of the reservoir. Case Studies from two different Giant Oil Fields located in the South of IRAQ are included in this paper, and each field has various sets of Data, varied from Pressure Test and NMR to only Full-Set of Wire line data. These fields were selected to represent various applications scenarios of Carbonate and Shaly-Sand Oil Bearing Formations of In-Situ Wettability using Nuclear Magnetic Resonance (NMR) log and Reservoir Characterization Instrument (RCI) Pressure Data. The novelty of this study offered advance integrated petrophysical evaluation for In-Situ Wettability to support the field development plans and improve the reservoir characterization.

Formation permeability is one important flow parameter associated with subsurface production and injection. Reliable Formation permeability values are often measured in laboratory from cores or evaluated from well test data. Well logs Derived Permeability are associated with high accuracy with NMR logging; However, NMR logging, core analysis and well test data are usually available for few wells / specified intervals in a field, while, almost all other wells are logged conventionally.The Procedure use Water Saturation and Effective Porosity Values as inputs; the Geological zonation is critical; each selected zone will be cross-plotted to evaluate the Irreducible water saturation factors then Archie's parameters for each level-by-level will evaluated using Gomes Iteration or Dialectic log method of Freeman et.al, afterward Pirson and Coates et al. methods will be utilized to calculate the reservoir permeability, these method improved to inclusive Archie's parameters, finally a Statistical convergence approach specifically Mean Absolute Error ЉMAEЉ method is utilize to validate the Results with other Permeability sources of Core, NMR and Pressure testing.Case Studies were selected from Super-Giant Oil Fields located in Middle and South of Iraq to test the model applicability, due to the availability of Pressure Testing, Core analysis, Dielectric log and NMR logging data in complex reservoirs of these field. key observations; There are no general Permeability model (equation) can characterize permeability even in subsequent formations and The Archie's Parameters have crucial effect on Permeability Values, the utilization of the proposed model have helped greatly to select the best-to-fit Permeability model for each Reservoir.There are several Permeability Models in lectures, the select of best-fitted-Model to a Reservoir was and will continue as a matter of discussion. The understand the permeability behavior is critical and in this study an Integrated Petrophysical Procedure (using the aid of Core Analysis, Crossplot and the computer iteration) was presented to select the best Permeability Model.The Novel significance of the proposed procedure were distinguished with its ease flexibility to include any other permeability model and it can be utilize in any other Oil Fields giving more understating to the permeability behavior in a selected reservoir.